Use of hydrocarbon emulsions as a reburn fuel to reduce nox emissions

ABSTRACT

An in-furnace combustion application process method and apparatus reduces nitrogen oxides in flue gas by injecting a bitumen, carbon residue or an asphalt water emulsion or a mixture thereof into flue gas so that the three types of emulsions (injected individually or as a blend) mixes with said flue gas. The emulsions are preferably atomized before injection and may also be injected in jet streams.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of International Application No.PCT/US2008/066537 filed Jun. 11, 2008, which claimed priority to U.S.Application No. 60/943,133 filed Jun. 11, 2007, each of which areincorporated herein by reference in their entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention relates to a method of reducing NO_(x) emissions fromvarious types of furnaces ranging from utility boilers to industrialpackage boilers to Once Through Steam Generators to refinery furnaces.

2. Description of Related Art

The art has long recognized the presence of NO_(x) in effluent gasesfrom various types of hydrocarbon burning devices and the desirabilityof reducing such NO_(x).

Masaki et al., U.S. Pat. No. 4,060,983, discloses that it is well knownto reduce the amount of NO_(x) in an engine by employing anon-stoichiometric air-fuel ratio [in automobile engine]

Zamanshy et al., U.S. Pat. No. 6,471,506, utilizes metal containingcompounds in a furnace reburn zone to reduce NO_(x).

Zauderer, U.S. Pat. No. 6,453,830, reduces NO_(x) by introducingsufficient fuel into the furnace downstream of the primary combustionzone into a fuel rich zone at a temperature that favors the conversionof NO_(x) to N2. Then further downstream air is added to completecombustion of any unburned fuel.

Additional fuel, where the fuel is pyrolysis gas from the partialgasification of a solid fuel, is introduced into a downstream combustionzone as solid particles dispersed in aqueous droplets of varying size.In other embodiments the fuel is a liquid fuel or is pulverized coal orshredded biomass particles.

In Zamansky et al., U.S. Pat. No. 7,168,947, a fuel rich zone isestablished containing a plurality of reduced n-containing species,introducing over fire air downstream of the fuel rich zone so that then-containing species react with the NOX in the overfire zone.

Arand et al., U.S. Pat. No. 4,325,924, introduces urea in the presenceof excess fuel as a solid or liquid at a temperature in excess of 1900°F.

Hura et al., U.S. Pat. No. 5,908,003, burns a solid fuel in a primaryzone and injects a gaseous fuel into a downstream fuel lean zone at atemperature of 1800 to 2400° F.

Breen et al., U.S. Pat. No. 6,213,032, injects a water-oil emulsion intoflue gas where the emulsion is 35-80% water. Urea or water may be addedto emulsion which is preferably atomized before injection.

Payne et al., U.S. Pat. No. 6,481,998, discloses an apparatus for highvelocity injection of liquid fuel into an NOX containing streamdownstream of the primary combustion chamber without using recirculatedflue gas or other carrier gas.

Reburn is a combustion hardware modification in which the NO_(x)produced in the main combustion zone is reduced downstream by providinga second combustion zone (the reburn zone). Up to 20% of the total fuelheat input to the furnace may be diverted from the main combustion zoneand introduced above the top row of burners to create reducing(sub-stoichiometric in O₂ terms) conditions in the reburn zone. Thereburn fuel is typically natural gas or micronized coal, a coal that ispulverized to 90% through a 300-mesh screen. The reburn fuel is injectedinto the furnace to create a fuel-rich zone where the NO formed in themain combustion zone is reduced to N₂, NH₃, HCN, other reduced nitrogencompounds and water vapor.

The reburn fuel may be injected alone or may be injected with a carryingmedium such as re-circulated flue gas to improve fuel distribution inthe furnace.

Combustion of the fuel-rich combustion gases leaving the reburn zone iscompleted by injecting overfire air (also called “completion air” whenreferring to reburn) in the burnout zone. At this point the NH₃, HCN,and other reduced forms are oxidized to N₂, and NO. At this step andthroughout the mixing process there is also a direct reaction between NOand NH₃ to form N₂. In each step, part of the fixed nitrogen (originallyNO) is converted to N₂ thus fulfilling the purpose of the reburnprocess.

The gas reburn principal can be implemented in several ways. Thetraditional approach involves overall fuel-rich gas reburn. NOcontaining furnace gases from the primary combustion zone enter adownstream gas mixing and reburn zone in which a sufficient flow rate ofnatural gas is injected to form an overall fuel-rich mixture,Essentially, a region in the secondary combustion zone is drivensub-stoichiometric.

The total fuel flow to the reburn zone of the furnace is typically inthe range of 10% to 20% of the total energy input utilized in thefurnace. Reburn reactions in the overall fuel-rich NO_(x) reductionreburn zone reduce NO to N₂, but produce relatively high levels of CO.Nitrogen in the reburn zone enters from the combustion gases from theprimary combustion zone and from nitrogen contained in the reburn fuel,if any.

This CO produced in the reburn zone is then reduced in a final burnoutzone by injecting completion overfire air to produce overall leanconditions in which oxidation of the reburn gas is completed. Suchconventional gas reburn technology has demonstrated NO_(x) reductionsabove 50% in many installations.

A related technology, the modified reburn process, can achievecomparatively moderate NO_(x) reductions, but at a much lower heat inputthan in conventional reburn furnaces, and without the need for acompletion overfire air system to achieve CO burnout. In the modifiedreburn process technology, natural gas or an emulsion of water and oilis injected into the upper furnace at sufficiently low rates to maintainoverall fuel-lean conditions in the upper furnace region. The NO_(x)reburning reactions then occur within local fuel-rich regions formed bythe gas injection and the mixing process.

Mixing between the injected reburn fuel and furnace gas is key toeffective NO_(x) control. CO burnout is achieved by the excess O₂available in the overall furnace flue gas, without the need for acompletion overfire air system. This technology has achieved 35% to 40%NO_(x) reductions at 7% burnout fuel heat inputs without significantimpact on the primary furnace combustion process.

Successful application of this modified reburn technology to any giveninstallation hinges on achieving proper mixing of the injected gas withfurnace gases to achieve optimum NO_(x) removal and low CO emissions.Uniform mixing of the injected gas will in most cases not produce thehighest NO_(x) removal efficiencies. The NO_(x) and CO performance ofthis technology thus depends on the location, size, shape and placementof the gas injectors, which determine details of the resulting gasmixing process. To date, the results indicate that maximum NO_(x)reductions of 35% at 7% maximum gas heat input levels are limited byincreased levels of CO emissions.

Attempts to maximize gas mixing are exemplified by the high velocityfuel injectors specified in Payne et al. U.S. Pat. No. 6,481,998 issuedNov. 19, 2002.

In those processes where a carrier gas is used to input the reburn fuel,the carrier gas maybe steam, air, or combustion products. Steam isexpensive. The use of air or recycled combustion products such as fluegas recirculation requires expensive ductwork, or the need for anexpensive flue gas recirculation fan. These fans are expensive tooperate and high maintenance items.

Micronized coal requires a long burnout time when utilized as a reburnfuel. Utilizing micronized coal as a fuel source requires that both thefuel and the completion air be added at an earlier point in the furnace.As a result, much of the reaction occurs at higher temperatures, whichresults in more NO_(x) emissions.

Where boilers use neat bitumen or heavy fuel oil as the primary fuel,with high concentrations of vanadium in the ash of the fuel, a SCR(Selected Catalytic Reduction) process will not be practical due to thenegative impact of the vanadium (in the form of Va₂0₅) on the catalystin the SCR.

In addition, the need for completion air in traditional reburn processesrequires that boiler pressure parts be modified (tube wall bending)which are expensive and can impact boiler water flow circulationpatterns and heat transfer characteristics.

The first installation and combustion optimization of natural gas as areburn fuel in the first full-scale utility boiler in the USA wasaccomplished in the Niles Station of Ohio Edison in the late 1980's on acyclone boiler.

The Electric Power Research Institute (EPRI) issued a report entitled“Gas Cofiring Assessment for Coal-Fired Utility boilers, EPRI, PaloAlto, Calif.: 2000, (10000513) considering the following:

Gas Reburning (RP)

Fuel Lean Gas Reburning (FLGR™)

Amine Enhanced Fuel Lean Gas Reburning (ALFLGR™)

Advanced Gas Reburning (AGR)

Supplemental gas cofiring

Coal/Gas cofiring burners

Although all of these reburn methods reduce NO_(x) emissions theindustry has been slow to adopt them.

Commercial technologies available for NOX reduction have disadvantagesthat create boiler operational problems or cannot achieve NO_(x) levelsbelow 0.15 lbs./MM Btu without using two or more of these technologies.

Selected Catalytic Reduction can achieve lowest NOx emissions levels butcreate operational and maintenance problems that impact costs and boileravailability.

Low NO_(X) Burners alone can not achieve the low NOx levels alonewithout adding Over Fire Air as an example. In addition, Low NO_(X)Burners' firing refinery gas can experience stability problems.

Over Fire Air creates the sub-stoichiometric conditions that lead to thehigh temperature vanadium corrosion attack.

Selected Non-Catalytic Reduction can not achieve low NOx levels (primaryobjective) and has high ammonia slip.

Traditional Reburn creates the sub-stoichiometric conditions that leadto the high temperature vanadium corrosion attack.

Advanced oil recovery methods, such as the Cyclic Steam Stimulationprocess (CSS) and the Steam Assisted Gravity Drainage (SAGD) process,use steam to extract oil in situ through the use of injected steam.Boilers used in these processes do not presently use reburn technology.

For many applications, the associated costs and installation problemsdiscussed above when considered against the projected level of NO_(x)emissions reduction has not been perceived to be worth the investment.

Thus, there continues to be a need for a reburn method/application whichprovides significant NO_(x) emissions reduction without requiringextensive duct work, FGR fans, and modifications to the boiler pressureparts.

SUMMARY OF THE INVENTION

Provided are a method and apparatus for reducing NO_(x) emissions inwhich a bitumen containing aqueous emulsion is injected into the fluegas of a furnace downstream of the primary combustion chamber andcombusted in an oxygen poor reducing environment to remove a significantportion of the NOx components in the combustion gases.

The disclosed method of introducing NO_(x) reduction into boilers usedfor the Steam Assisted Gravity Drainage oil sands Steam Assisted GravityDrainage application (OTSG & package drum boilers), refinery furnaces,or utility boilers will maintain overall stoichiometric conditions above1.0 throughout the boiler and specifically in the primary furnace.

All four of the current NOX reduction technologies—Selected CatalyticReduction, Low NO_(x) Burners, Over Fire Air, Selected Non-CatalyticReduction and traditional reburn—have serious problems when applied tothe boilers used for the Steam Assisted Gravity Drainage process whenusing alternative fuels in oil sands applications, refinery boilers andutility boilers.

The emulsion is a hydrocarbon in water emulsion where the hydrocarboncomponent may itself be an emulsion of varying composition in theaqueous component of the emulsion.

The aqueous component of the emulsion may be composed simply of water ormay contain nitrogenous compounds such as urea or ammonia.

The hydrocarbon component is preferably composed of bitumen, vacuumresidue, or asphalt or a mixture thereof where the individual componentsof the hydrocarbon emulsion may vary greatly in proportion.

The oil in water emulsion is injected into the secondary combustionregion of the furnace above the primary combustion zone in a manner thatcreates oil in water bilayered droplets with an external aqueous layerof water alone or in combination with urea, or ammonia and an innerhydrocarbon layer of bitumen, vacuum residue or asphalt or mixturethereof.

It is preferable that the droplets are evenly distributed throughout theinput stream and not broken when the emulsion passes through theatomizer or injector into the furnace. The emulsion droplets are sized(Sauter Mean Diameter (SMD) by the atomizer/injector, so that the jetpenetration and evaporation rate allow for the formation of localizedfuel rich contrary currents.

In the localized fuel rich contrary currents created in the furnace bythe carefully adjusted injection of the reburn fuel into the secondarycombustion region, the droplets provide secondary atomization(micro-explosions) as the liquid aqueous outer droplet layer vaporizesto steam and releases the smaller hydrocarbon droplets which createlocalized fuel rich contrary currents.

It is preferable to provide injectors that are in several planes of thefurnace to cover a range of regions in the furnace.

As the NO_(x) emissions from the primary combustion zone passes throughthe currents rich in reburn fuel in the reburn zone the NO_(x) arereduced to N₂, HCN, and other reduced nitrogen entities.

The use of the reburn fuel disclosed herein and the process ofminimizing NO_(x) emissions solves many of the existing problemsassociated with present systems and lowers the installation andmaintenance costs of NO_(x) emission control systems.

Other objects and advantages of this application, method and apparatusinvention will become apparent from a description of certain preferredembodiments shown in the attached figures.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a conceptual diagram of the contrary current local cloudNO_(x) reduction process in accordance with the present invention.

FIG. 2 is a process flow diagram, which shows the fuel handling andemulsion making process of the reburn fuel for delivery to theatomizers/injectors.

FIG. 3 is an example of a dual fluid atomizer/injector using eithersteam or sour solution gas as an atomizing fluid and the resultantprimary and secondary atomization process used to both set up thelocalized fuel rich contrary currents and introduce the fixed reducednitrogen agent in accordance with the present invention.

FIG. 4 is a diagram showing one embodiment of the fuel injector deliverysystem of the present invention.

FIGS. 5 & 6 are diagrams of a utility boiler and Once Through SteamGenerator furnace to which injectors have been added in accordance withthe present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

NO_(x) components in the combustion gases from a furnace are reduced byinjecting a bitumen containing aqueous emulsion into the flue gas of afurnace downstream of the primary combustion chamber and combusted in anoxygen poor reducing environment to remove a significant portion of theNO_(x) components in the combustion gases.

As used herein “sour gas solution” means natural gas that is not refinedand often contains species such as hydrogen sulfide (H₂S) in the 2000PPM range.

As used herein, “atmospheric tower bottoms” (ATB) or straight runresidue, is the byproduct that remains and reflects the fraction or cutof the refining distillation curve representing products with a boilingtemperature >800° F. (>426.7° C.).

As used herein, “vacuum residue” means the fraction that remains afterdistillation of bitumen or crude oil under either atmospheric (ATB orAtmospheric Tower Bottom) or vacuum (VTB or Vacuum Tower Bottom)conditions that contains fewer volatiles. Straight run residue or ATB isa byproduct that remains and reflects the fraction or cut of therefining curve representing products with a boiling temperature greaterthan or equal to 800° F. (426.7° C.). The typical application of thisbottom product (VTB) is feed to an asphalt plant, a thermal cracker, acoker, or as a blending component for residual fuel (#6 HFO).

These bottom fractions or high boiling residues are also used as asphaltor residual fuel oil (#6 HFO). Asphalt is one of two availablealternatives the refiner or upgrading process may consider for thesebottom residues, depending upon the quality of the bitumen and theavailable market.

The asphaltene concentration determines the quality of the asphalt.Asphaltenes are very complex molecular substances found naturally inneat bitumen, which impart a high viscosity to the residue appearingsolid at room temperature. Asphaltenes consist of polyaromatic compoundswith high carbon-to-hydrogen ratios (˜1:1.2 depending on source) definedoperationally as the n-heptane insoluble, toluene soluble component ofcarbonaceous material, such as crude oil or bitumen.

As bitumen is processed, the asphaltene concentration increases. A morecomprehensive technical definition for asphaltenes is contained in ASTMtest method D 6560.

As used herein, “Solvent De-Asphalter” (SDA) is the next step along therefining process, which operates at an even higher temperature to handlean even more viscous product. The SDA process uses a hydrocarbon solventtailored to ensure the most economical de-asphalting design. Propanesolvent is typical for the low-de-asphalted oil or a heavier residue orbitumen. Designs have been developed to produce a maximum yield ofde-asphalted oil and minimum yield of asphalt, the latter having aviscosity range of 60,000 cp at 530° F. (276.7° C.) with a very highconcentration of asphaltene.

As used herein, “bitumen” means a mixture of highly viscous primarilyhighly condensed polycyclic aromatic hydrocarbons. Naturally occurringor crude bitumen is a sticky, tar-like form of petroleum. Refinedbitumen is obtained by fractional distillation of crude oil. It is theheaviest fraction and the one with the highest boiling point, boiling at525° C. (977° F.). Most bitumens contain sulfur and several heavy metalssuch as nickel, vanadium, lead, chromium, mercury and also arsenic,selenium, and other toxic elements.

Naturally occurring crude bitumen is the prime feed stock for petroleumproduction from oil sands currently under development in Alberta,Canada. Canada has most of the world's supply of natural bitumen. TheAthabasca oil sands is the largest bitumen deposit in Canada and theonly one accessible to surface mining, although recent technologicalbreakthroughs have resulted in deeper deposits becoming producible byin-situ methods.

As used herein “neat bitumen” is a product extracted from oil sands(typically using the SAGD or CSS process), is very viscous and is alsoreferred to as non-conventional oil or crude bitumen to distinguish itfrom the freer-flowing hydrocarbon mixtures.

As used herein “burnout air” or “overfire air” means the air introducedto the furnace downstream of the reburn zone to complete combustion in aburnout zone downstream of the reburn zone

Emulsion

The fuel utilized in all embodiments of the invention comprises anemulsion of a hydrocarbon and water. Depending of the relativequantities of each present, the emulsion may be an oil in water emulsionor a water in oil emulsion. The two types of emulsions functiondifferently in the instant process.

Where the emulsion is a hydrocarbon in water emulsion the hydrocarboncomponent may itself be an emulsion of varying composition in theaqueous component of the emulsion.

The droplet size is an important characteristic and may range indiameter from 60 to 300 micrometer or larger encasing 5 to 30micrometers of inner droplet, preferably from 60 to 300 micrometerencasing 5 to 20 micrometers of inner droplet.

Aqueous Component

The aqueous component of the emulsion may be composed simply of water ormay contain nitrogenous compounds such as urea or ammonia.

Where the emulsion is enhanced with a fixed nitrogen reagent, theinstant process will allow the water to volatilize first and result inthe process chemistry to take place in the fuel rich clouds (localsub-stoichiometric air to fuel ratios) created by the small droplets ofhydrocarbons from the inner bilayer of the fuel droplets released by thesecondary atomization process.

The emulsion comprises an aqueous phase comprising from 1% to 32% of thetotal volume (1 to 43% by weight) of the droplet, preferably 20% to 32%by volume (30 to 43% by weight), most preferably 15% to 25% by volume(20 to 34% by weight).

The oil in water emulsions usable comprise 5 to 25, preferably 5 to 20micron size hydrocarbon droplets (SMD) in larger (80 to 300 micron)water droplets. The size of the hydrocarbon droplets which form thecenter portion of the water droplets is determined by the process bywhich the emulsion is formed and by the micro explosions of thevaporized aqueous surface of the droplets that serves to disperse thehydrocarbons. The injector and/or atomizer is the delivery system thatdistributes the 80 to 300 micron droplets of the oil in water emulsionto the furnace (primary atomization).

The water in oil emulsions usable comprise 80 to 300 micron sizehydrocarbon droplets (SMD) established by the injector and/or atomizer(primary atomization) with the size of the smaller water dropletsencompassed within the droplet determined by the emulsion process andare typically in the range of 5 to 30 microns or larger dispersed in theoil emulsion droplets.

In this process the micro explosions of the individual dropletsdetermine the hydrocarbon droplets size (secondary atomization).

The percentage of water in oil in water emulsions is in the range ofabout 10 to 32% with optimum percentage water in the 20 to 30% range.The percentage of water in water in oil emulsions is in the range ofabout 1 to 10% with the optimum percentage water in the 5 to 8% range.

The emulsion can also be made from a urea solution or aqueous ammoniasolution where the normal stoichiometric ratio (NSR) which defines theconcentration of the solution (amount of urea, etc.) based on the amountof NO_(x) emissions exiting the primary flame zone is between 1 and 3.An example of the calculation using NH₃ (17 molecular weight) to NO_(x)as NO₂ (46 molecular weight) is for NSR=1:

NH₃ (tons)=[NO_(x) (tons)][17/46]

and for NSR=1.5:

NH₃ (tons)=[NO_(x) (tons)][25.5/46]

The aqueous phase of the droplets provides a means of control of thereaction temperature in the fuel rich zones, which will improve the NOremoval.

Hydrocarbon Component

The hydrocarbon component is preferably composed of bitumen, atmosphericresidue, heavy fuel oil, vacuum residue, asphalt, or solventde-asphalter or a mixture thereof where the individual components of thehydrocarbon emulsion may vary greatly in proportion.

The amount of the hydrocarbon component in the hydrocarbon emulsion isas follows:

Bitumen: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% byweight.

Atmospheric residue: 57 to 99%, preferably 60 to 85%, most preferably 65to 80% by weight.

Heavy fuel oil: 57 to 99%, preferably 60 to 85%, most preferably 65 to80% by weight.

Vacuum Residue: 57 to 99%, preferably 60 to 85%, most preferably 65 to80% by weight.

Asphalt: 57 to 99%, preferably 60 to 85%, most preferably 65 to 80% byweight.

Solvent de-asphalter: 57 to 99%, preferably 60 to 85%, most preferably65 to 80% by weight.

The hydrocarbon emulsion of bitumen, atmospheric residue, heavy fueloil, vacuum residue, asphalt, or solvent de-asphalter is produced byproviding high shear to the materials as shown in FIG. 2. The mixture ofhydrocarbons forms an emulsion in which the bitumen, vacuum residue (VTBand SDA), or asphalt droplets are small enough so that a majority ofthem do not break or coalesce when the emulsion is stored in a day tankor passes through the atomizer/injector into the furnace.

Furnace Temperature

To reduce the NO_(x), the emulsion of water (only or fixed nitrogenenhanced water) and hydrocarbon is introduced into the boiler after theprimary combustion zone in a region where the temperature is in therange of about 2000° F. to 2600° F. or about 1100° C. to 1427° C., asshown in FIG. 1.

Preferably, the emulsion is injected into regions of the furnace inwhich the flue gas temperature is between 1900° F. (1038° C.) and 2600°F. (1427° C.), preferably between 1900° F. (1038° C.) and 2350° F.(1288° C.), most preferably between 1900° F. (1038° C.) and 2200° F.(1205° C.).

The process is designed to allow the disclosed reburn fuel to react withthe oxygen in the reburn combustion process and to burn out almostcompletely. The emulsion is designed and produced so the aqueous phaseis the continuous phase and the hydrocarbon phase is dispersed in theaqueous phase as very small droplets (SMD=5 to 15 micrometers).

In this manner the volatization of the hydrocarbons present in thehydrocarbon phase is delayed while the water volatilizes. The delay maybe finely tuned to the type of furnace and combustion conditions so asto achieve and maintain a desired temperature in the secondarycombustion, region to maximize NO_(x) removal consistent with themaintenance of other suitable operating conditions. This procedureresults in the lowest possible emissions of NO_(x) at the lowest cost.

In general, it is preferred to operate reburn fuel at temperatures thatare as low as possible, while still being able to complete the burnoutof the reburn fuel. This increases the NO_(x) reduction potentialdirectly proportional to the decrease in equilibrium NO_(x) as thetemperature decreases.

However, where the fuel is very economical it is possible to overcomethis temperature limitation by using more reburn fuel. Where the reburnfuel emulsion contributes and amount in the range of 8% to 20% of thetotal heat input to the furnace, it is necessary to use a large amountof completion air.

If no completion air is used and an amount of reburn emulsion, in therange of 1% to 7.9% of the total heat input is used it is only necessaryto assure that the primary furnace is sufficiently air rich to supplythe oxygen for burnout.

Where the emulsion is made from materials that are less expensive thanthe base fuel, higher quantities of heat inputs of reburn fuel may beused to achieve higher NOx reductions.

The temperature window of the presently described process is much widerthan other reburn and Selected Non-Catalytic Reduction (SNCR) processes.

The temperature window is 19000 F (1038° C.) to 2600° F. (1427° C.). Theemulsion is from 5% to 32%, preferably 20 to 30% aqueous phase andadjustments can be made to accommodate different furnaces or furnaceconditions.

The emulsion is injected into fuel rich areas (sub-stoichiometricconditions) of the furnace and the secondary atomization and watervolatization takes place in the localized fuel rich regions.

The ratio of aqueous phase to hydrocarbon phase in the droplets may bemodified to provide an aqueous phase within the range of 5% to 34% tofurther modify the very local reburn temperature.

Amount of Reburn Fuel

In one embodiment, the heat input from these emulsified fuels is between1% and 20% of the total boiler heat input. In a preferred embodiment,the heat input from these emulsified fuels is between 2% and 7.9%. Mostpreferably the heat input from these emulsified fuels is between 5% and7%.

The droplet has an outside diameter in the range of 60 to 300 microns orlarger, preferably 80 to 300 micron, most preferably 120 to 300 micron.The oleophilic inner droplet layer has a diameter of from 5 to 25micron, preferably 6 to 20 micron, most preferably 6 to 15 microndroplets.

The reburn reaction takes place in the fuel rich contrary currents ofthe furnace zone down stream of (see attached figures for injectionlocations) the primary flame zone.

Where the aqueous phase of the emulsion contains urea or aqueousammonia, an additional NO_(x) reduction is obtained from the secondaryatomization characteristics of the emulsion releasing the fixed reducednitrogen agents in the fuel rich contrary currents or the deep stagedregions of the primary flame zone prior to the introduction of overfireair.

Although overfire air can be used in the instant process the preferredmethod is not to use overfire air.

These agents improve the NO_(x) reduction by reacting with the NO_(x) toform N₂. The fact that this reagent reaction takes place in a localizedor deep staged (localized fuel rich contrary currents) fuel richenvironments allows for the process to perform effectively at a widerand higher temperature range (1900° F. to 2600° F.) for peak reductionefficiency of the reagents in a localized reducing environment.

This is the reason for not using overfire air in the most preferredembodiment because driving the entire furnace sub-stoichiometric (totalreducing environment in the furnace) causes rapid corrosion of theboiler tubes and tube hanger metals in the boiler due to hightemperature accelerated vanadium corrosion attack.

This is when compared to traditional SNCR which take place in anoxidizing environment with a narrow temperature window (1750° F.+/−50°F.). These are bell curves and the wider temperature range for thelocalized reducing environments gives the NOx reduction process moreflexibility and improved NOx reduction efficiency without causingaccelerated corrosion.

The instantly disclosed method allows for lower NSR and the least amountof ammonia slip. The most preferred temperature range for this inventionis 1900° F. to 2200° F. where peak NO_(x) reduction efficiency forlocalized reducing environment is obtained with an NSR=1 to 1.5.

CO burnout is achieved by the excess oxygen available in the fuel gasfrom the primary flame zone, without the need for a completion overfireair system (OFA) or in the deep staged condition with the introductionof OFA.

Injection

The emulsion is introduced both as streams (jets) and spray droplets,usually in combination to assure better coverage.

FIG. 3 shows an example of a single “Y” jet dual fluid atomizerproviding primary atomization using the energy from the atomizer andsecondary atomization from the emulsion to both release the fixednitrogen reagent and create the fuel rich local cloud (contrarycurrents). In addition, a low-pressure mechanical atomizer can be usedto inject the emulsion into the furnace. Preferred methods ofintroducing the burnout fuel utilize either dual fluids using soursolution gas or low pressure (100 to 250 PSI range) mechanicalinjectors. The most preferred injection method utilizes low pressure(125 to 200 PSI range) mechanical injectors.

Different sized jets and atomized drops can be used depending upon therequirements of the specific furnace. The droplet size utilized isboiler and site specific and the determination of optimal sizing is wellwithin the competence of those skilled in the art to determine.

Atomizing Fluid

Sour solution gas is a preferred atomizing fluid in theatomizers/injectors. Other atomizing fluids such as steam may be used.

The ratio of sour solution gas or steam to emulsion product in theatomizers/injectors is in the range of 0.05:1 to 0.5:1 atomizing fluidto emulsion product, preferably in the range of 0.05:1 to 0.20:1, mostpreferably in the range of 0.05:1 to 0.10:1 of sour solution gas orsteam to the emulsion (on a pound per pound basis of atomizing fluid tofuel). In a highly preferred embodiment low pressure mechanicalinjectors requiring no atomizing fluid are utilized.

Chemistry

The chemistry of the process is complex and involves over thirty (30)chemical reactions. For illustrative purposes, the process can berepresented by one (1) basic equation which occurs in a localizedreducing atmosphere at a temperature in the range of about 1100° C. and1425° C.:

NO_(x)+NH₃+H₂O+H₂→N₂+H₂

The kinetics involved in the reburn zone to reduce NO_(x) are complex.The chemical reactions involved in the reburning process were firstproposed by J. O. L. Wendt in the late 1960's (Wendt et al, 1973). Thefollowing discussion, derived from a report published by the U.S.Department of Energy (Farzan and Wessel, 1991), is based on the conceptsintroduced in this work. The major chemical reactions follow. In thepresence of heat & 0₂ deficiency in local clouds the reaction processshown in Equation 3.1.1-1 shows hydrocarbon radical formation in thereburn zone.

CH₄→CH₃ ⁺+H⁺ (hydrocarbon radicals)  (3.1.1-1)

These hydrocarbon radicals are produced due to the pyrolysis of the fuelin an oxygen-deficient, high temperature environment. The hydrocarbonradicals then mix with the combustion gases from the main combustionzone and react with NO to form CN radicals, NH₂ radicals, and otherstable products (Equations 3.1.1-2 to 3.1.1-4).

CH₃ ⁺+NO→HCN+H₂O  (3.1.1.2)

N₂+CH₃ ⁺→NH₂ ⁺+HCN  (3.1.1.3)

H+HCN→CN⁺+H₂  (3.1.1.4)

The CN and NH₂ radicals and other products can then react with NO toform N₂, thus completing the major NO_(x) reduction step (Equations3.1.1-5 to 3.1.1-7)

NO+NH₂ ⁺→N₂+H₂O  (3.1.1.5)

NO+CN⁺→N₂+CO  (3.1.1.6)

2NO+2CO→N₂+2CO  (3.1.1.7)

An oxygen-deficient (reducing atmosphere) environment is critical tothese reactions. If 0₂ levels are high, the NO, reduction mechanism willnot occur and other reactions will predominate (Equations 3.1.1-8 and3.1.1-9).

CN+0₂→CO+NO  (3.1.1-8)

NH2+O₂→H₂O+NO  (3.1.1.9)

To complete the combustion process, the excess air (0₂) from the primaryflame zone is used to complete the fuel burnout after the local reburnzones have reduced the NOx emissions. Conversion of HCN and ammoniacompounds in the burnout zone may regenerate some of the decomposedNO_(″) by the reactions.

Although some additional NO_(x) may be formed in the burnout zonethrough these reactions, the net effect of the reburn process is toreduce significantly the total quantity of NO_(x) emitted by the boiler.

The bilayer emulsion is preferably introduced through atomizing nozzlesor injectors, which can handle the bilayer emulsion without breaking itdown, and through jets for maximum penetration and optimum droplet sizedistribution.

The atomizers can include internal mixing, “Y” jet, and “F” jet dualfluid atomizers with a range of spray angles, including cone shapedspray angles, flat sprays, individual finger sprays and single jetsprays. These dual fluid atomizers (see FIG. 3 as example) can usevarious atomizing fluids with either steam or sour solution gas as thepreferred atomizing fluid and sour solution gas as the most preferredatomizing fluid.

The ratio of atomizing fluid to emulsion product can range from 0.05:1to 0.5:1 preferably from 0.05:1 to 0.20:1, most preferably from 0.05:1to 0.10:1.

Operating pressures may range from 20 PSIG to 150 PSIG, preferably from75 to 125, most preferably from 100 to 125 for dual fluid injectors. Thepreferred injection method utilizes either dual fluids using soursolution gas or low pressure (100 to 250 PSI range) mechanicalinjectors. The most preferred injection method utilizes low pressure(125 to 200 PSI range) mechanical injectors.

Burnout or Completion Air is Used

In an embodiment of the invention where burnout or completion air isused, reburn fuel droplets are delivered to the total furnace reburnregion.

Burnout or Completion Air is Not Used

In an embodiment of the invention where no burnout air is used, thereburn area, the area of the furnace where the furnace atmosphere is areducing atmosphere, is injected with the reburn fuel without mixing anyof the reburn fuel into other areas of the furnace where the oxidizingatmosphere is left unchanged.

FIG. 4 shows an example of a multi-nozzle fuel handling and deliverysystem to be used to inject the emulsion products into the furnace atseveral furnace planes, levels, and areas.

In an embodiment where no burnout air is used and a face fired oropposed fired utility boiler is used it is preferred to establish wherethe lanes of reducing mixtures are located and inject the reburnemulsion into these lanes while maintaining oxidizing lanes between theinjection lanes.

The relative width of the lanes depends upon the amount of oxygen in theinitial combustion products, the final amount of oxygen, and how muchadditional fuel will be injected into the reducing lanes. The absolutewidths will be sufficient to allow almost complete volatilization andcombustion of the hydrocarbon reburn fuel in the reducing zone. Theevaporation of the urea and/or aqueous ammonia, if present in theemulsion, takes place in these reducing lanes, thus allowing for thefixed nitrogen reagent to be activated in these reducing lanes.

Furnace Type

In an embodiment of the invention where a tangentially fired utilityboiler is used, it is preferred to introduce streams of emulsion oneabove the other in each corner of the furnace. Atomized streams maybeintroduced with the jets to assure complete coverage in the proper SMDrange so the secondary atomization process takes place in the reducingatmosphere locations of the furnace. It is not necessary to introducethe emulsion into every corner. The same general arrangement of thebitumen, vacuum residue, or asphalt water emulsion injection would beused with and without completion air.

In an embodiment of the invention where a Cyclone furnace is utilized,the NO_(x)'s present are treated in the furnace after the combustiongases have exited the cyclones. A lane arrangement is best unlesscompletion air is used.

In an embodiment of the invention utilizing the SAGD or CSS process orrefinery furnace, where no burnout air is used in a Once Through SteamGenerator (OTSG), a package drum boiler, a field erected industrialboiler/furnace or a horizontal pass type “D” package boiler, it ispreferred to introduce streams of reburn fuel emulsion into lanes ofreducing mixtures established by the primary burner/atomizer (fingers offuel rich fuel), by injecting the emulsion into these lanes andmaintaining oxidizing lanes between these lanes. The relative width ofthe lanes depends upon the amount of oxygen in the initial combustionproducts, the final amount of oxygen, and how much surplus fuel is to bein the reducing lanes. The same general arrangement of reburn fuelemulsion injection is used with or without completion air.

In an embodiment of the invention utilizing a Circulating Fluidized Bed(CFB) boiler where no burnout air is used, it is preferable to establishalternate lanes of reducing mixtures exiting the Circulating FluidizedBed, by injecting the reburn fuel emulsion into these lanes andmaintaining oxidizing lanes between the injection lanes. The relativewidth of the lanes depends upon the amount of oxygen in the initialcombustion products, the final amount of oxygen, and how much surplusfuel is to be in the reducing lanes. The same general arrangement ofreburn fuel emulsion injection is used with and without completion air.

FIGS. 5 & 6 show examples of the reburn injection without completion airin both a Once Through Steam Generator and a face fired utility boiler.

The inventive process does not require carrier air, steam, orre-circulated flue gas. The atomizing fluid is preferably sour solutiongas used at heat inputs ranging from 0.35% to 2% of the total heat inputof the boiler.

With this invention expected NOx reductions can range from 25% to 65% ofthe total NO_(x) exiting the primary flame zone.

The foregoing specification describes certain presently preferredembodiments of the inventive method but it should be understood that theinvention is not limited thereto but may be variously embodied withinthe scope of the following claims.

1. A method of reducing NOx emissions from a furnace comprisingintroducing a hydrocarbon-water emulsion into the flue gas of thefurnace in a reburn zone downstream of a primary combustion zone wherethe hydrocarbon in the emulsion is selected from bitumen, atmosphericresidue, heavy fuel oil, vacuum residue, asphalt, solvent de-asphalter,and mixtures thereof.
 2. The method of claim 1 where a fixed reducednitrogen compound is added to the emulsion prior to introduction intothe furnace.
 3. The method of claim 2 where the fixed reduced nitrogencompound is urea or aqueous ammonia.
 4. The method of claim 2 where anamount of fixed reduced nitrogen compound is added such that the numberof atoms of reduced nitrogen are in the range of 0.25 to 3 times thenumber of atoms of NO_(x) in the primary combustion products.
 5. Themethod of claim 1 where the hydrocarbon component of the emulsion is 57to 99% by weight of the emulsion.
 6. The method of claim 1 where thehydrocarbon component of the emulsion is 65 to 80% by weight of theemulsion.
 7. The method of claim 1 where the emulsion is introduced intothe flue gas by injection in the form of atomized droplets.
 8. Themethod of claim 7 where the atomized droplets comprise an innerhydrocarbon droplet surrounded by an aqueous outer layer.
 9. The methodof claim 7 where the atomized droplets comprise an inner aqueous dropletsurrounded by a hydrocarbon outer layer.
 10. The method of claim 9 wherethe atomized droplets are from 60 to 300 micrometers in diameter. 11.The method of claim 9 where the atomized droplets are from 80 to 300micrometers in diameter and encase an aqueous droplet of from 5 to 30microns in diameter.
 12. The method of claim 8 where the atomizeddroplets are from 120 to 300 micrometers in diameter and encase ahydrocarbon droplet of from 5 to 20 microns in diameter.
 13. The methodof claim 1 where the flue gas at the point of introduction of theemulsion is at a temperature of from 1900° F. to 2600° F.
 14. The methodof claim 1 where the flue gas at the point of introduction of theemulsion is at a temperature of from 1900° F. to 2200° F.
 15. The methodof claim 1 where the amount of energy input from the hydrocarbon inwater emulsion comprises from 1 to 20% of the total energy input to thefurnace.
 16. The method of claim 15 where the amount of energy inputfrom the hydrocarbon in water emulsion comprises from 1 to 7.9% of thetotal energy input to the furnace and no burnout air is supplied to thefurnace.
 17. The method of claim 15 where the amount of energy inputfrom the hydrocarbon in water emulsion comprises from 8 to 20% of thetotal energy input to the furnace.
 18. The method of claim 1 furthercomprising introducing burn-out air at a location after or downstream ofthe place where the emulsion is injected.